1. Field of the Invention
This invention relates to a method for recovering oil from a subterranean formation, and more particularly to special surfactant systems to be used with waterflooding techniques to improve the oil displacement efficiency of waterfloods.
2. Description of the Prior Art
The petroleum industry has recognized for many years that only a portion of the original oil in an oil reservoir can be produced by what is referred to as "primary recovery," i.e. where only initial formation energy is used to recover the crude oil. It is also well known that conventional methods of supplementing primary recovery are relatively inefficient. Typically, a reservoir retains over half its original oil even after the application of currently available "secondary" recovery techniques. Accordingly, there is a continuing need for improved recovery methods which will substantially increase the ultimate yield of petroleum from subterranean reservoirs.
"Waterflooding" is by far the most economical and widely practiced of secondary recovery methods. In such a process, water or other aqueous fluid is introduced through injection wells to drive oil through the formation to offset producing wells. Much of the current work in secondary recovery technology has been directed toward improving the efficiency of waterflooding processes.
Surface-active agents or surfactants are one class of materials which have been proposed for improving the efficiency of waterflooding processes. Much of the oil that is retained in the reservoir after a typical waterflood is in the form of discontinuous globules or discrete droplets which are trapped within the pore spaces of the reservoir. Because the normal interfacial tension between the reservoir oil and water used for flooding is so high, these discrete droplets are unable to deform sufficiently to pass through narrow constrictions in the pore channels of the formation. When surfactants are added to the flood water, they lower the interfacial tension between the water and the reservoir oil and permit oil droplets to deform, coalesce and flow with the flood water toward producing wells. It is generally accepted that the interfacial tension between the surfactnt-containing phase and the reservoir oil must be reduced to less than 0.1 dyne/cm for low-tension flooding to give effective recovery.
One difficulty in the use of surfactants in general and anionic surfactants in particular is their tendency to be depleted from the injected solution as the solution moves through the reservoir. The surfactants tend to be lost by precipitation as insoluble salts of ionic materials, such as polyvalent metal ions, that may be dissolved in the fluid in the reservoir; by adsorption on the reservoir rocks; by physical entrapment within the pore spaces of the rock matrix; and/or by chemical conversion, such as hydrolysis of an active component of the surfactant system to a component that is insoluble, inactive, or detrimental in that system. If the surface-active agent is removed from the waterflood solution as it moves through the reservoir, the agent is not available to act at the oil/water interface. Quite naturally, surfactant depletion decreases oil recovery efficiency.
In a waterflood oil recovery process where the water contains a surfactant, the efficiency of the oil displacement is strongly affected by (1) the rate of surfactant loss and (2) the surface activity (extent of lowering of the oil/water interfacial tension) of the surfactant.
Another difficulty observed in the use of many anionic surfactants is the inability of the surfactant to exhibit high surface activity in high temperature reservoirs (i.e., temperatures of about 120.degree. F. or more) and/or in aqueous solutions containing high concentrations of inorganic salts. Thus, many oilfield brines, e.g. formation brines which are considered herein to contain high concentrations of inorganic salts, generally contain over 2% NaCl and over 0.5% CaCl.sub.2 and MgCl.sub.2 total; concentrations of over 4% NaCl and 2% CaCl.sub.2 and MgCl.sub.2 are common. (All percentages reported herein are percents by weight, unless otherwise noted.) As used herein, the term formation brine includes not only brine originally present in the formation but also brines subsequently introduced into the formation, e.g. during flooding operations. Of course, formation brines are encountered which do not contain such high concentrations of inorganic salts, but generally such brines are less common and in any event still contain what would be considered "high" concentrations of inorganic salts by most standards.
When the typical salt concentrations of many formation brines are considered, it is not surprising that development of suitable surfactants for reservoir environments has met with little success. As mentioned, formation brines often contain concentrations of sodium chloride ranging from 2% to over 10%, and combined calcium and magnesium chloride concentrations from 0.5% to over 2.0%. These concentrations may range up to the solubility limits of said salts in water at formation temperature. To place the development of surfactants useful under reservoir conditions in perspective surfactants useful as detergents in hard water contemplate salt concentrations which are orders of magnitude less, e.g. sodium chloride concentrations no higher than about 0.2% and combined calcium and magnesium chloride concentrations of no more than 0.05%. In fact, most detergent surfactants are entirely unsuited for use in reservoir environments.
Further examples of the typically high formation brine salt concentrations may be found in A. G. Ostroff, "Introduction to Oilfield Water Technology", p. 5 (1965). For comparison, typical water hardness values in the detergent art may be found in K. Durham, "Surfact Activity and Detergency," p. 96, 98 and 137-142 (1961).
The problem is further complicated by the fact that although a given surfactant may be soluble in formation brines, this is no assurance that it will be effective in lowering interfacial tensions sufficiently for enhanced oil recovery.
Generally, as the temperature of the reservoir and concentration of inorganic salts in the brine solution of the reservoir increase, the surfact activity of conventional anionic surfactants decreases. Surfactants have been suggested which exhibit some tolerance to either high temperature or high salt concentrations. None of these surfactants, however, have the ability to exhibit a high degree of surface activity under all types of reservoir conditions, including high salt concentrations or high temperature, or both high temperature and high salt concentration reservoirs.
It has generally been found that positioning an ethoxy group adjacent to the sulfonate or sulfate group of a given surfactant tends to increase the solubility of such surfactant in water; moreover, increasing the number of ethoxy groups tends to increase the water solubility of such surfactants and also provides improved solubility characteristics in water having high concentrations of inorganic salts such as sodium chloride, magnesium chloride, and calcium chloride. Accordingly such surfactants have been proposed for use in environments having high concentrations of such inorganic salts.
Thus, it has been reported in U.S. Pat. No. 3,508,612, issued to Reisberg et al, that a two-component surfactant mixture exemplified by a petroleum sulfonate and a salt of a sulfated polyalkoxylated alcohol (e.g. C.sub.12-15 O(C.sub.2 H.sub.4 O).sub.3 SO.sub.3 Na) exhibits improved tolerance against high salt concentration environments. It has been found, however, that the surface activity of the two ingredients in this composition is very sensitive to the salt content of the brine. This sensitivity is important because in commercial operations concentrations may vary from time to time and because the concentration of the surfactant composition will vary as it moves through the formation because of mixing with in-situ water, non-uniform movement and the like. This results in both surfactant loss to the formation and loss of surface activity.
A major cause of the problems associated with the use of polyalkoxylated surfactants is due to the fact that as the fluid containing these surfactants moves through a formation, a chromatographic-type separation of surfactant components takes place. This may be better understood by considering the general chemical composition of a polyalkoxylated surfactant. Generally, such surfactants are prepared by alkoxylating a suitable organic substrate using a strong base or a Lewis acid catalyst such as sodium hydroxide, BF.sub.3 or the like, followed by sulfation or sulfonation. While the resulting product may be purified to some extent, the resulting "pure" surfactant ultimately used in the field is, in reality, a mixture of discrete compounds, each having been alkoxylated to a different extent. For example, when ethoxylating a primary alcohol, ROH, the resulting product may be represented as RO (EO).sub.4.2 H (where EO represents the ethoxy group (C.sub.2 H.sub.4 O) and the subscript 4.2 indicates the average number of ethoxy groups). Actually, the product comprises a mixture of adducts and unreacted alcohols, for example EQU R OH, RO(EO).sub.1 H, RO(EO).sub.2 H, RO(EO).sub.3 H, RO(EO).sub.4 H, RO(EO).sub.5 H, RO(EO).sub.6 H, . . . , RO(EO).sub.12 H, . . .
and so forth, in different proportions such that an average value of 4.2 ethoxy groups has been achieved. It has been found that each component compound demonstrates a substantially different surface activity at a given concentration of inorganic salts.
Thus, while the surfactant may possess some properties similar to a purified, single component surfactant and may give acceptable results in small scale laboratory tests, field results can vary substantially due to extensive chromatographic-type separation of one or more components during flooding. A less subtle variation of this problem has been noted previously where a mixture of two (or more) different types of surfactants (cosurfactants) are utilized, such as the approach suggested in U.S. Pat. No. 3,811,505, issued to Fluornoy et al.
Thus, as the surfactant-containing fluid moves through the vast distances of a reservoir (compared to short laboratory cores), the various surfactant components separate. Each separated component is in a similar environment, i.e. reservoir brine of a given inorganic salt concentration. However, except for that discrete component whose properties are acceptable in the reservoir brine, all remaining components exist in an unacceptable environment. In other words, all other discrete components, when separated, will demonstrate poor surface active properties in the reservoir brine.